This invention relates to methods for and fluids used in treating a subterranean formation. In particular, the invention relates to the preparation and use of polymer delivery systems in the form of concentrated polymer suspensions useful for creating wellbore fluids and in methods of treating subterranean formations.
Various types of fluids are used in operations related to the development and completion of wells that penetrate subterranean formations, and to the production of gaseous and liquid hydrocarbons from natural reservoirs into such wells. These operations include perforating subterranean formations, fracturing subterranean formations, modifying the permeability of subterranean formations, or controlling the production of sand or water from subterranean formations. The fluids employed in these oilfield operations are known as drilling fluids, completion fluids, work-over fluids, packer fluids, fracturing fluids, stimulation fluids, conformance or permeability control fluids, consolidation fluids, and the like, and are collectively referred to herein as well treatment fluids.
Water-soluble polymers are frequently used for modifying the rheology, e.g. viscosification, proppant suspension, friction reduction, etc., in a number of subterranean formation treatment fluids, including fracturing fluids, wellbore cleanout fluids, gravel pack fluids, and the like. Creating these fluids often involves the steps of dispersing and hydrating polymers, such as guar, cellulose, and derivatives thereof, into a water stream. Hydration of polymers for oilfield applications is generally a slow process. The process normally involves at least a few minutes of agitating the polymer, either a hydrocarbon slurry or dry polymer, with water in a flow path that contains different compartments. Although the process and hydration time has been shortened through multiple efforts in the past decades, it is still not as quick as desired, i.e. reaching above 80% final fluid viscosity in less than 1 or 1.5 minutes. The long hydration time requires the operation to have a specific hydration unit, such as a Precision Continuous Mixer (PCM), on top of a blending unit, such as a Programmable Optimum Density (POD) blender. The equipment and energy costs of this process are high.
Guar powders are generally obtained through a grinding process. The guar particles generally have a twisted, plate-like structure that can be observed under a microscope. Upon contact with water, the twisted structures quickly unwind into layered structures that are more flat. As these structures are intercalated by absorbing more water, they swell unevenly into larger plates wherever they contact water. With uneven swelling between the layers, and assisted by some agitation, the layers exfoliate to almost individual sheets. The final step is to completely dissolve the swollen plate structures into individual molecular coils. In the hydration process, the swelling and exfoliation steps occur rapidly, usually in less than 10 seconds. The exfoliated plate dissolution step is much slower and also depends on the degree of agitation. The last step is the longest, usually accounting for about 50-70% of the total time for the complete hydration process.
It is known that the smaller the polymer particles, the more surface area that can contact the aqueous phase and the faster the hydration process. However, there have been several issues associated with the use of very small guar particles. Grinding the dry guar polymer can have a detrimental effect on the polymer performance because the grinding process can physically break the molecular chains and thus lower the polymer molecular weight and therefore lower the ultimate gel viscosity yield. In addition, the smaller the particle size, the harder it is to grind in terms of grinder geometry, energy input, heat dissipation control, and so on, which in turn lead to higher costs. Furthermore, when particles are small, they tend to form fish-eyes during hydration, where the outermost particles of an agglomerate quickly hydrate to a thick gelatinous material that encapsulates the interior particles of the agglomerate and prevents the water from entering into the core for further hydration. Thus, the knowledge that finer particles will potentially shorten hydration time has not led to effective improvements to reduce the time to complete the hydration process.
Historically, oilfield polymer solutions were gelled in batch mixing processes by which dry polymer was mixed with water in tanks large enough to hold all the fluid for a wellbore treatment. These batch treatment processes had numerous limitations since gel once made could decompose from bacteria, and any gel not used at the wellsite was wasted. Additionally, batch mixing did not readily allow for changes in gel concentrations or loading during the course of a treatment. Accordingly, numerous technologies have been developed to allow continuous mix of polymer solutions at a wellsite. A successful technique for gelling an aqueous fluid must meet several criteria, including but not limited to allowing accurate metering of polymer material into a water stream, producing hydrated polymer fluids with a minimum amount of equipment, while also avoiding the formation of fish-eyes when polymer particles contact water.
Continuous mix systems commonly in use typically use non-aqueous slurries or dry powder systems. Non-aqueous slurries comprise dry polymer suspended in an oil solvent, often diesel fuel which presents some difficulties. To minimize the use of oil suspensions, service companies have also developed dry systems in which dry polymer is directly mixed with water, but such systems can present another set of difficulties known to those of skill in the art. Some examples of complicated polymer hydration equipment are disclosed in U.S. Pat. No. 5,190,374, U.S. Pat. No. 5,382,411, U.S. Pat. No. 5,426,137 and US 2004/0256106.
Similar difficulties are encountered when adding a friction reducer such as acrylamide homopolymer or copolymer to low viscosity fracturing fluids known as slickwater fluids, which typically contain only 0.025 to 0.2 weight percent of the friction reducer, in addition to other conventional additives such as biocides, scale inhibitors, clay stabilizers such as potassium chloride, trimethylammonium chloride or the like. Friction reducers are available commercially in oil or oil-and-water emulsions. To reduce turbulent flow in the slickwater fluid, the friction reducer must “flip” from the emulsion to rapidly dissolve in the water, usually within several seconds, or else the full drag reduction will not be achieved during transit through the wellbore. Surfactants have been used in the friction reducer emulsions to shorten the flip time. Also, dilution of the friction reducer in a brine solution has been used to collapse ionic polymer chains and reduce the viscosity of the concentrated friction reducer solution; however, storage stability has been an issue because any contact with fresh water, such as condensate dripping inside a storage tank, immediately forms fisheyes, which cannot be redispersed. It should be noted that the fisheyes form even thought the low viscosity brine-diluted polyacrylamide mixtures are clear solutions indicating no phase separation.
In the food industry, two-phase aqueous fluids are used to create polymer solutions that mimic the properties of fat globules. In the biomedical industry, such systems are exploited as separation media for proteins, enzymes, and other macromolecules that preferentially partition to one polymer phase in the mixture. When two or more different water soluble polymers are dissolved together in an aqueous medium, it is sometimes observed that the system phase separates into distinct regions. For example, this happens when two polymers at high concentration are chosen that are each water-soluble but thermodynamically incompatible with each other, e.g. polyethylene glycol (PEG) and dextran. Such two-phase systems are variously referred to in the literature as water-in-water emulsions, biphasic systems, aqueous two phase systems (ATPS) or the like. Although they may be referred to as emulsions they do not necessarily contain either oil or surfactant.
Although numerous continuous mix systems are now in the oilfield, none is completely satisfactory, and considerable need remains for systems with improved hydration properties. This need is met at least in part by the following invention.